Well logging methods and apparatus

ABSTRACT

In accordance with illustrative embodiments of the present invention, techniques are disclosed for compensating acoustic well logging measurements for variations in one or more conditions of a well bore. More particularly, these measurements are compensated for variations in well bore cross-section, and well bore fluid acoustic impedance and velocity. These compensation techniques have particular significance in connection with systems of the type which scan a well bore wall by rotating a transducer means which emits directional bursts of high frequency acoustic energy and receives energy reflected off the bore wall. The electrical signals produced by this received energy are suitably processed to provide information relative to the character of the media forming the well bore wall.

Unite States Ptet 151 3,676,842 Lee July 11, 1972 [54] WELL LOGGING NETHODS AND 2,379,996 7 1945 Silverman ..340Il5.5 AC

APPARATUS Primary ExaminerMalcolm F. l-lubler [72] Inventor: Jimmy G. Lee, Houston, Tex. Asst-3mm Examiner N Moskowitz [73] Assignee: Schlumberger Te hnolog C r o ti Attorney-Leonard R. Fellen, Donald H. Fidler, Stewart F.

New York, NY. Moore, Jerry M. Presson, Edward M. Roney, William R. Sher- Filed: Dec. 1969 man and John P. Smnott [21] Appl. No.: 888,579 [57] ABSTRACT In accordance with illustrative embodiments of the present in- [52] U.S. Cl ..340/15.5 BH, 340/18 OS, 340/18 AC vention, techniques are disclosed for compensating acoustic [5]] Int. Cl ..G01v 1/28, GOlv l/36 well logging measurements for variations in one or more con- [58] Field of Search 340/ 15.5 8H, 18 OS, 18 AC, ditions of a well bore. More particularly, these measurements 340/18 DR are compensated for variations in well bore cross-section, and well bore fluid acoustic impedance and velocity. These com- References C'ted pensation techniques have particular significance in connec- UNITED STATES PATENTS tion with systems of the type which scan a well bore wall by rotating a transducer means which emits directional bursts of 3,312,934 4/1967 Stripling et a]. ..340/ 18 P high frequency acoustic energy and receives energy reflected 3,304,536 2/1967 Kokesh ..340/l8 P off the bore wall. The electrical signals produced by this 3,297,983 7 mm r 05 received energy are suitably processed to provide information 3,369,626 2I1968 Zemanek, BL relative to the character of the media forming the well bore 3,148,352 9/1964 Summers ....340/l8 OS wall 3,390,377 6/1968 Elliott et a1. ..340/l8 OS 3,503,038 3/1970 Baldwin IMO/15.5 BH 1 26 Claims, 19 Drawing figures OSCILLOSCOPE RECORDER SWEEP TRIGGER INTENSITY SURFACE ELEC TRON/C L 38 3 CIRCUITS A c f w k i *2 7 fi i 3 i V 7 6 I o 8 x CABLE 28 I 12 FROM FILTER98 51%? i IG 4 V, W f IL,E WE E 1 M LX w "/12s 1 I 7 o I M TIME TO I Qf I AMPLITUDE; 5 i 73 E CONVERTEn V725 s I VAR/ABLE I I I3 Maw/ER i V SIGNAL AMPLITUDE I l 1 l COMPENSATION CIRCUIT i i a L l 1 F Y f ELEtgIT-G i 30 1 HOU IN LIMITER ENABLE l 1 l CIRCUIT GATE Bil-MODULATOR 5 l I I g P 31" I DIRECT/0N GATE SENSING 1 UNIT '9- l 34 l i l 1 "-11 l 5 l I I GATE 1 l l 33 1 DELAY l 1 I ONE-SHOT I i 15 i 2\6 25 27 DIRECTIONAL E TR/gDgCER Asixgiygg/zgcm ACCOUSTIC N a "T I rRANsDucERi CIRCUIT MULTIVIBRATOR ONE SHOT Y i \77 I n...n

Patented July 11, 1972 3,676,842

5 Sheets-Sheet 2 68 T0 PROCESSING TEAL/PER cIRcUIT m ggggggg I INTEGRATOR 1 I 1 CURRENT N INTEGRATOR 5 I DETECTOR E IP-FL P R 1 cIRcUITs 72 IIvTEGRATDR 73 CONTROL TX 70 I I DATA 7 5 i \TRANSFER l AUTO AT/C 1 DATA T T oIvE-sHor I f GATE N L LL-I i c0IvTROL INPUT 59 I i I BUFFER I l I AMP I 67a f0 8 l L78 l I/SX' I I TIME TO AMPLITUDE /57 T0 REcoRDER coNvERTER A I 4 L L 28\ D6ILNEG FIG. 2 CABL E DRIVING cIRcUIT 46 I I VAR. 2 21% I OSCILLATOR DEMODU-LATORS 6 60-g I I l I L T LOW PASS I FILTER I GATE 5 T I I PULSE GATE I 1 GENERATING 5X to cIRcUIT I RESET FROM j 57 54 DIFFERENCE DEMOD. 31 I 4 7 PEAK cIRcUIT F/G.7

AMPLIFIER GATE 5 56 I I CIRCUIT I RES/ET 49 I 55 48 Jimmy G. Lee

I PEAK IIvvEIvToR SAMPLE8 AMPLIFIER GATE HOLD I cIRcU/T 5Y7 in 53 I ATTORNE Y Patented July 11, 1972 3,676,842

5 Sheets-Sheet 5 TRANsM/TTER F/R/NG PULSE U FL F/G.3A

RECEIVER R, Wm. 35

RECEIVER R2 Wm 3C GATE 52 3D ENABLE PULSE GATE 53 3E ENABLE PULSE OUTPUT GATE 1 l PULSE TRANSMITTER [1 l F /G 6 A FIRING PULSE RECEIVER 5x7 55 SIGNAL GATE 92 5 c ENABLE PuLsE GATE 30 6 D E NA BLE PULSE M E1 5H Jimmy G. Lee

INVENTOR ATTORNEY Patented July 11, 1972 3,676,842

5 Sheets-Sheet &

CAL/PER L RECORDER c/Rcu/T o \N T 58 CONTROL INPUT X2 o 9 7 T/ME T0 fii i J LOW PASS 5 x2 FILTER 95 SIGNAL PROCESS/N6 c/Rc U/TS 94 A suRFA (:E i A fifi J JR DOWNHOLE D R GTN G 91 3 c/Rcu/Ts F 5)(] GATE DEMODULATOR GATE DEMODUL ATOR TIMING TRANSDUCER ASYMMETR/CAL TRANSDUCER FIRING ASTABLE c/Rcu/ T MULT/V/BRATOR ONE SHOT 61 Jimmy 6. Lee 2 T //vvE/vT0R 5% ATTORNEY This invention relates to methods and apparatus for investigating the media forming a well bore and, more particularly, to that type of well logging system which employs transmission of acoustic energy towards the well bore wall and measurement of energy reflected from the wall.

In well bore systems of the type involved here, the well bore is scanned through 360 by a rotating transducer means which repetitively emits directional bursts of high frequency acoustic energy during each rotation while it is moved through the well bore. For each burst of transmitted energy, the reflected energy is detected and is primarily dependent upon the character of the media surrounding the well tool including the mud velocity, distance to the well bore wall, and formation or casing acoustic impedance.

The reflected energy is converted to a pulse signal and displayed on an oscilloscope in variable density form where the horizontal sweep of the scope beam is synchronized to the rotation of the transducer to provide one sweep for each 360 rotation. Each beam sweep is synchronized with an azimuthal orientation of the transducer. A recording medium moves past the face of the oscilloscope in synchronism with the movement of the well too] through the borehole to provide a picture of the media comprising the well bore wall.

A system for investigating the media forming a well bore as set forth above is shown and described in copending application Ser. No. 827,799, filed on May 26, 1969 by Joseph E. Chapman, Ill. While the system set forth in this Chapman application provides good results, there is, as always, room for improvement. In the Chapman system, the diameter of a well bore is measured by measuring the elapsed time for acoustic energy to travel from the transducer to the well bore wall and back again. However, for this elapsed time measurement to be accurately indicative of well bore diameter, the acoustic velocity of the fluid contained in the well bore must be accurately known. Normally, the average acoustic velocity throughout the full length of the well bore can be determined and suitable adjustments made in the elapsed time computing circuits to account for the well bore fluid velocity. However, such things as well bore pressure and temperature may cause this well bore fluid velocity to vary from depth level to depth level thus affecting to some degree the elapsed time or well bore diameter measurements.

It is therefore an object of the present invention to compensate well logging measurements for variations in the acoustic velocity of the fluid contained in the well bore.

In the above-mentioned Chapman system, as stated earlier, a picture of the well bore wall is produced by repetitively reflecting acoustic energy off of this well bore wall and suitably processing the signals produced by the acoustic transducer. The received energy signals, in addition to being used to produce a picture, are also processed in such a manner to produce a curve representative of the lithology of the formation surrounding the well bore. This lithology information is obtained by measuring the RMS amplitude of the received energy signals for every 360 scan of the well bore wall.

The amplitude of the signal received by the acoustic transducer is dependent upon the impedance of the formation surrounding the well bore and the attenuation by the mud in the well bore through which the signal travels.

Unfortunately, the attenuation of the signal by the well bore fluid may vary from depth level to depth level. The primary cause of this variation is change in the distance between the acoustic transducer and the borehole wall. A secondary cause of this variation is brought about by changes in the acoustic impedance of the mud itself.

It is therefore another object of the present invention to provide new and improved methods and apparatus for compensating well logging measurements for variations in the acoustic attenuation of the fluid contained in a well bore.

In accordance with the present invention, methods and apparatus for investigating the media forming a well bore comprises moving a well logging tool having single transducer means through a well bore and repetitively energizing the transducer means to emit acoustic energy into a media surrounding the well tool. A transmitted energy sync signal representative of the time that energy is emitted and a received energy signal representative of at least a portion of the emitted energy which is returned to the well tool are produced by the transducer means every time the transducer is energized. The invention further comprises producing a measurement signal in response to at least one of the sync and received energy signals representative of a characteristic of at least part of the media surrounding the well tool, measuring at least one parameter of the media surrounding the well tool which afiects the accuracy of the measurement signal and producing a control signal representative of the parameter. The control signal is then used to compensate the measurement signal for variations in this parameter of the surrounding media.

For a better understanding of the present invention, together with other and further objects thereof, reference is had to the following description taken in connection with the accompanying drawings, the scope of the invention being pointed out in the appended claims.

Referring to the drawings:

FIG. 1 shows a well tool in a borehole along with a schematic representation of the apparatus arranged in accordance with one embodiment of the present invention;

FIG. 2 shows a section of a well tool along with a schematic representation of apparatus arranged in accordance with another embodiment of the present invention;

FIGS. 3A-3F illustrate waveform displays of various signals found in the apparatus of FIG. 2;

FIG. 4 illustrates a section of a well tool constructed in accordance with another embodiment of the present invention;

FIG. 5 is a schematic representation of electrical circuitry which can be utilized in connection with the well too] apparatus of FIG. 4;

FIGS. 6A-l-I illustrate a waveform display of signals found at various locations in the FIG. 5 apparatus; and

FIG. 7 shows a portion of the FIG. 5 circuitry in greater detail.

Referring now to FIG. 1, a well tool 10 isschematically illustrated as disposed in a well bore 11 on the end of an armored multiconductor cable 12. The well bore 11, which can be cased or open hole, contains a drilling liquid 13 and traverses earth formations 14. The cable 12 is spooled on a suitable drum and winch mechanism (not shown) which raises and lowers the tool 10 through the borehole 11.

The well tool 10 includes an electrical motor 15 which drives a shaft 16 at a constant rotational speed to rotate a directional acoustic transducer 17 and a direction sensing unit 18. The directional acoustic transducer 17 operates to repetitively and directionally emit and receive acoustic energy as it is rotated, the received acoustic energy primarily being reflected from the wall of the well bore 11. The tool is desirably centralized in the well bore I1 by suitable means (not shown).

The direction sensing unit 18 operates to provide an output signal representative of the orientation of the acoustic transducer 17 relative to the housing of the well tool 10 and a signal representative of the orientation of a fixed point on the circumference of this housing relative to magnetic north. These output signals are transmitted to the surface of the earth on conductors l9 and 20.

The well tool 10 also includes a fluid tight and gas proof electrical housing unit 21 which contains the downhole electrical circuitry. The details of this electrical circuitry are shown in the dotted line box 21a to the right of the borehole 11 for purposes of illustration.

In the electrical housing unit 21, an asymmetrical astable multivibrator 25 generates a signal which operates to periodically energize a transducer firing circuit 26 for energizing the transducer 17 via a conductor 28 to emit acoustic energy towards the wall of the well bore 1 l. The multivibrator 25 also energizes a t, one-shot 27 which operates to supply a pulse to a suitable cable driving circuit 28 each time the transducer 17 is energized.

When the directional transducer 17 is energized, it emits acoustic energy which is directed toward the wall of the well bore 1 l, reflected off this wall, and returned to the transducer 17 which produces an electrical signal representative of the acoustic energy impinging on the transducer 17. This received electrical signal is supplied to the receiver channel of the downhole electrical circuitry from the conductor 28. This receiver circuitry comprises a limiter 29, enable gate 30, demodulator 31 and a well fluid compensation circuit 32. The limiter circuit 29, on the input of the receiver channel, prevents the high energy pulses from the transducer firing circuit 26 from upsetting the operation of or damaging the receiver channel circuits. The enable gate 30 is energized only during a time interval when the receiver signal from transducer 17 is expected so that the firing pulse from the trans: ducer firing circuit 26 or noise will not be mistaken for authentic received energy signals from the transducer 17. To accomplish this timing operation, the asymmetrical astable multivibrator 25 energizes a gate delay one-shot 33 which operates to energize a gate one-shot 34 a fixed time interval later. The output pulse from the gate oneshot 34 energizes the enable gate 30 to enable the received energy signal from transducer 17 to be passed to the demodulator 31. This gated signal is then demodulated by the demodulator 31 which produces a signal pulse corresponding to the envelope of the high frequency signal from transducer 17. This received energy signal (in the form of a pulse), designated s is then applied to the signal amplitude compensation circuit 32 for further processing in accordance with the present invention. The processed s, signal, designated s is then applied to the cable driving circuit 28 for transmission to the surface of the earth.

Before discussing the operation of the signal amplitude compensation circuit, it would first be desirable to discuss the problem that the signal amplitude compensation circuit is designed to solve. As discussed earlier, the system shown and described in the above-mentioned copending Chapman application produces quantitative information regarding the lithology of the formations adjoining the well bore as well as a picture of the well bore wall. This picture is made by sweeping an oscilloscope beam across the face of an oscilloscope in synchronism with the rotation of the directional acoustic transducer 17 and intensity modulating the scope beam in proportion to the magnitude of the reflected energy received by the transducer 17, i.e., the amplitude of the received energy s, signals from demodulator 31.

However, the magnitude of this received energy can vary as a function of factors other than the condition of the well bore wall and the lithology of the adjoining formations. One such factor which tends to affect the amount of received energy is variations in well bore diameter. Whenever the well bore diameter changes, the amount of reflected energy received at the transducer 17 can vary because of attenuation attributable to the altered distance which the acoustic energy must travel to and from the transducer 17. As concerns the lithology log and picture of the well bore wall, this change in distance has no meaningful information, only the acoustic impedance of the media surrounding the well bore wall has such meaningful information. (It should be noted however that the system of the copending Chapman application includes well bore diameter measuring circuitry which obtains diameter information independent of the amount of reflected energy received at the transducer 17.)

Turning now to the signal amplitude compensation circuit 32, this circuit operates to compensate the amplitude of the received energy signals from demodulator 31 as a function of the diameter of the well bore. To accomplish this, the s, signals from demodulator 31 are applied to a variable gain amplifier 34a whose gain is controlled by a control signal from a time-to-amplitude converter 35. The variable gain amplifier 34a produces an output signal s, which is the input s, signal compensated for variations in borehole diameter.

The time-to-amplitude converter 35 is responsive to the t, and s, signals for producing an output signal whose amplitude is representative of the time spacing between these signals. (If desired, the s signals could be used in place of the r, signals.) A variable resistor 36 connected to the converter 35 can be adjusted to account for the velocity of the mud contained in the well bore 11. The time-to-amplitude converter 35 can take any suitable form such as for example, the time-to-amplitude conversion circuit used for well bore diameter measurements shown in the copending Chapman application.

The DC type control signal from the converter 35 is then applied to the variable gain amplifier 34 via the low-pass filter 37 and a variable resistor 37a to adjust the gain thereof in accordance with variations in well bore diameter. The low-pass filter 37 serves to present occasional erroneous time measurements (like missing s, signals) from adversely affecting the gain control operation. The variable resistor 37a can be set as desired to give the proper correction function (i.e., to calibrate the system).

At the surface of the earth, the transmitter firing timing pulse t and compensated received energy signal s, are applied to the surface electronic circuits 38 which can take the form shown in the copending Chapman application. These surface electronic circuits 38 utilize the timing pulse 1,, as an aid in accurately detecting the received energy signal s, and then process the s, signal for application to the intensity input of an oscilloscope recorder 39. The details of this oscilloscope recorder 39 can be found in copending application Ser. No. 829,159, filed on May 26, 1969 by Theodore F. Brunn.

The orientation signals from the direction sensing unit 18 which are transmitted to the surface of the earth via conductors l9 and 20 are also applied to the surface electronic circuits 38. The circuits 38 process these signals to produce a signal suitable for periodically triggering the horizontal sweep input of the oscilloscope recorder 39. Thus, the orientation signals cause the oscilloscope beam to be repetitively swept across the face thereof while the beam is being modulated in intensity by the processed s, signals from the surface electronic circuits 38.

In addition to the effects of variations in well bore diameter on the measurements, the attenuation by the well bore fluid itself can vary from depth level to depth level causing other possible inaccuracies to result in the amplitude of the received energy signals s,,. Turning now to FIG. 2, there is shown apparatus for accurately measuring this fluid attenuation and compensating the received energy signals for variations in well bore fluid attenuation. A section 45 of the well tool includes an acoustic transmitter T and two spaced apart acoustic receivers R, and R (schematically shown) positioned such that acoustic energy passing between the transmitter T and receivers R, and R will pass only through the well bore fluid. The receivers R, and R should be spaced far enough apart to provide a reasonably high signal level but close enough together to give good resolution. The transmitter to receiver spacing should be great enough to prevent the initial ringing portion of the acoustic wave from being picked up by the receivers and close enough to enable a measurable signal level to be produced by the receivers. The frequency of the transmitted acoustic energy should be high enough that the emitted energy will stay within the confines of the wellbore. Desirably, this frequency should be the same as the frequency of acoustic energy emitted by the rotating transducer 17. The rotating acoustic transducer 17 and direction sensing unit 18 could, for example, be located below these acoustic transducers. The acoustic receivers R, and R are displaced radially from one another so that the acoustic receiver R, will not intercept the energy passing to the lower receiver R Regarding the electrical circuitry of FIG. 2 and referring to FIGS. 2 and 3A-3F in conjunction, an oscillator 46 periodically energizes the transmitter T as represented by the waveform of FIG. 3A. The resulting acoustic energy emitted from the transmitter T strikes the receivers R, and R at times which are dependent on the distance between the transmitter T and each receiver R, and R as well as the acoustic velocity of the well bore fluid. The difference in energy arriving at the receivers R and R is dependent on the spacing between the receivers R and R and the acoustic attenuation of the well bore fluid. The signals produced by the receivers R and R are shown in FIGS. 38 and 3C respectively. These receiver signals are applied to a pair of amplifiers 47 and 48 via a pair of potentiometers 49 and 50 respectively.

The oscillator 46 output signal is applied to a gate pulse generating circuit 51 which operates to generate the gating pulses shown in FIGS. 3D and 3E. These gating pulses are generated fixed time intervals after each transmitter firing pulse of FIG. 3A. These time intervals correspond to the expected time of arrivals of energy at the two receivers. The gate enable pulse of FIG. 3D energizes an enable gate 52 so as to pass the receiver R signal and the gating pulse of FIG. 3E energizes an enable gate 53 so as to pass the receiver R signal. The gated R, receiver signal is applied to a peak sample and hold circuit 54 which stores a voltage proportional to the peak amplitude of the receiver R signal and holds this voltage until the circuit is eventually reset. The peak sample and hold circuit 55 performs the same operation on the gated R receiver signal.

The stored peak voltages from circuits 54 and 55 are applied to a difference circuit 56 which operates to subtract the amplitude of the voltage stored by the sample and hold circuit 55 from that stored by the sample and hold circuit 54 to produce an output signal proportional to the difference between the energy received by the two acoustic receivers R and R This difference signal is then gated to a low-pass filter 57 by a gate 58 which is energized by the output gate pulse of FIG. 3F from the gate pulse generating circuit 51. The output signal from the lowpass filter 57 is then applied to a variable gain amplifier 59 via a variable resistor 60 to adjust the gain of amplifier 59. The low-pass filter 57 operates to smooth out the fluctuations produced by the gating operation of gate 58 as well as to minimize the affect ofoccasional noise.

The received energy signals 3, from the demodulator 31 of FIG. 1 (not shown in FIG. 2) are supplied via the variable gain amplifier 59 to the cable driving circuit 28 for transmission to the surface of the earth. The peak sample and hold circuits 54 and 55 are periodically reset by the transmitter firing pulses from the oscillator 46.

From the foregoing, it can be seen that the FIG. 2 circuitry described thus far operates to measure the acoustic attenuation of the fluid contained in the well bore 11 and adjust the gain of variable gain amplifier 59 as a function of this measured attenuation so that the compensated received energy signals 5, will be corrected for the effect of attunation of acoustic energy by the well bore fluid. Thus, the amplitude of the s, signals will be a function of the characteristics of the well bore wall and acoustic impedance of the formation.

The system of FIG. 2 can be calibrated by inserting the well tool in water and adjusting the potentiometers 49 and 50 until the output signal from low-pass filter 57 substantially nulls. Since water has very little acoustic attenuation, the amplitudes of both the R and R receiver signals should be the same when the tool is in water and thus the output signals from difference circuit 56 should have zero amplitude. The potentiometer 60 is adjusted to give the desired correction function.

As discussed earlier, the system of the copending Chapman application also operates to measure the well bore diameter by measuring the time for acoustic energy to pass from the rotating transducer 17 of FIG. 1 to the well bore wall and back again. This type of well bore diameter measurement provides extremely accurate results provided that the velocity of the well bore fluid is always known. Unfortunately, in the present practice, this well bore fluid velocity is not always accurately known. Therefore, in accordance with another feature of the present invention, this fluid velocity is measured at the same time that the rotating directional transducer 17 is scanning the well bore wall and the circuits utilized for computing the well bore diameter are adjusted as a function of changes in the well bore fluid velocity. The apparatus of FIG. 2, along with compensating the amplitude of the s, signals, also operates to make this well bore fluid velocity adjustment.

To accomplish this velocity adjustment, in FIG. 2, the gated R and R receiver signals are demodulated by suitable demodulators 62 and the demodulated signals applied to the cable driving circuit 66 for transmission to the surface of the earth. At the surface of the earth, the gated R and R receiver signals are utilized to adjust certain parameters in the caliper (well bore diameter) circuit to compensate the diameter measurements for variations in well bore fluid velocity. Before explaining how this compensation operation is carried out, it would first be desirable to briefly discuss the operation of the caliper circuit.

Referring to the surface located circuitry of FIG. 2, the t and s, signals are applied to an automatic gain control circuit 69 which utilizes the amplitude of the t signals to control the amplitude level of the s, signals. Since the t signals are always of a constant amplitude when transmitted from the well too], the signal amplitude of the s, signals can be normalized by utilizing the amplitude of the 1,, signals for gain control purposes. The normalized t and s, signals are then applied to detector circuits 70 which operate to accurately detect the t and s, signals and generate timing pulses designated T and T, representative of the arrival times of the t and s, signals respectively. These timing pulses T, and T, are then applied to a caliper circuit 68 which operates to convert the time separation between these timing pulses to a signal whose amplitude is proportional thereto.

Thus, looking at the caliper circuit 68 in detail, each '1', pulse sets an integrator flip-flop 71 and each T, pulse resets it. The normal output of the integrator flip-flop 71 energizes an integrator current switch 72 which generates a constant current during the time interval that the integrator flip-flop 71 is set. This time interval is, of course, equal to the time spacing between each successive T and T, pulse. The current from the integrator current switch 72 is applied to an integrator 73. The integrator 73 includes a capacitor which charges up to a voltage proportional to the time separation between each successive T and T, pulse. After the capacitor of integrator 73 has had an opportunity to charge to such a voltage, the trailing edge of each T, pulse energizes a data transfer one-shot 75 which operates to energize a data transfer gate 76. When the data transfer gate 76 is energized, the voltage output of the integrator 73 is transferred to a storage capacitor 77 for appli cation to a buffer amplifier 78 and recorder.

To compensate the well bore diameter measurements for variations in well bore fluid velocity, the gated R and R receiver signals are applied to a time-to-amplitude converter 67. The converter 67 operates to measure the time interval between each set of these two pulses and produce an output signal whose amplitude is representative of this time spacing. This output signal is filtered by a low-pass filter 67a and applied to the integrator current switch 72 via a variable resistor 67b to regulate the current output of the current switch '72. The current regulation circuit portion of the current switch 72 could take any suitable form. The filter 67a serves the same purpose as the filter 57 and the variable resistor 67b can be set as desired to provide the necessary correction function.

Summarizing the operation of the FIG. 2 apparatus, the acoustic transmitter T is periodically energized by the oscillator 46 to emit acoustic energy into well bore fluid, which acoustic energy is received by the acoustic receivers R and R The peak amplitude of the energy received by each acoustic receiver R and R is stored in the sample and hold circuits 54 and 55. The difference circuit 56 measures the amplitude difference between these two energy levels to produce an output signal proportional to the acoustic attenuation of the well bore fluid. This difference signal is periodically gated to the low-pass filter 57 so as to produce a DC type control signal proportional to this fluid attenuation for adjusting the gain of the variable gain amplifier 59 thereby compensating the s signals for mud attenuation.

At the same time, the time separation between each set of receiver signals from the receivers R and R is measured and converted to a DC type control signal proportional to this time separation by the time-to-amplitude converter 67. This control signal is utilized to adjust the amount of current being applied to the integrater 73 of the caliper circuit to thereby compensate the well bore diameter measurement for variations in the well bore fluid acoustic velocity.

Turning to FIG. 4, there is shown an alternative form of apparatus which can be used to measure well bore fluid velocity. In FIG. 4, the well tool includes a main section 81 and a lower section 80 of reduced diameter. Between the sections 80 and 81 is disposed an inclined section 82 with a small shoulder 83 between the upper end of the inclined section 82 and the main section 81. The rotating directional acoustic transducer 17 is positioned in the section 82 and is bordered by an acoustic absorbing member 84a which prevents acoustic energy from radiating in the wrong direction. At least a portion of the inclined section 82 is made of a suitable accoustically transparent material so that the accoustic energy from the transducer can be coupled to the media surrounding the well tool. An acoustic reflecting member 84 is positioned at one circumferential location on the periphery of the well tool 10 so as to reflect at least one burst of acoustic energy back to the transducer 17 during each 360 revolution of the transducer 17, Thus as the acoustic transducer 17 rotates, it will normally transmit energy to the wall of the well bore 1 1, which energy is reflected back to the transducer 17. However, at the circumferential location where the reflecting member 84 is located, the acoustic energy will be intercepted by the member 84 and quickly returned to the transducer 17. Since the reflecting member 84 has a smoothsurface, and is a fixed known distance from the transducer 17, the amount of time which the acoustic energy takes to travel from the transducer 17 to the reflecting member 84 and back again is dependent only on the acoustic velocity of the well bore fluid. This well bore fluid velocity information can then be used to adjust the caliper circuits to compensate for variations in the well bore fluid velocity.

Turning now to FIG. 5, there is shown a diagram of electrical circuitry which can be utilized to make such an adjustment for fluid velocity. In the FIG. 5 circuit, many of the elements are the same as the similarly designated elements of FIG. 1 and need not be discussed in detail. Briefly covering these similar elements and referring to FIGS. 5 and 6A-6H in conjunction, the asymmetrical astable multivibrator 2S periodically energizes the transducer firing circuit 26 and the 1,, oneshot 27 with the pulses shown in FIG. 6A. The transducer firing circuit 26 energizes the transducer 17 to emit acoustic energy into the media surrounding the well tool and receives energy reflected back from the well bore wall except when the energy is reflected from the acoustic reflecting member 84. The energy received by the transducer 17, represented by the signals of FIG. 6B, is supplied via the limiter 29 to the gate 30 which is energized during the appropriate time interval by the gate enable pulse of FIG. 6D to select the acoustic energy reflected from the well bore wall. This gate enable pulse is generated by a timing circuit 90 in response to output signals from the multivibrator to select the well bore wall reflected energy represented by the signal s of FIG. 6B. The timing of the gate enable pulse is selected in accordance with the distance between the transducer 17 and reflecting member 84 and the expected range of the accoustic velocity of the well bore fluid (plus a suitable safety factor). The gated receiver signal from the gate is demodulated by the demodulator 31 and applied to the cable driving circuits 91 as the signal pulse S The transducer firing timing signal t,, is also applied to the cable driving circuits 91 for transmission to the surface of the earth.

The circuitry of FIG. 5 also operates to detect the amount of energy received by the transducer 17 which has been reflected off of the acoustic reflecting device 84. Since the reflecting device 84 is relatively close to the transducer 17, the acoustic energy received by the transducer 17 which has been reflected off of the reflecting member 84 will appear much sooner than the energy reflected off of the borehole wall. To accurately detect this initial reflected energy represented by the waveform S in FIG. 6B, the timing circuit enables a gate circuit 92 during the time interval that this initial received energy signal is expected. The gate 92 enable pulse is shown in FIG. 6C. The gated S signal is applied to a demodulator 93 which produces the received energy signal S of FIG. 613. This signal S is also applied to the cable driving circuits 91 for transmission to the surface of the earth.

At the surface of the earth, the transmitted t,,, 5,, and S signals are applied to signal processing circuits 94 which operate to normalize the amplitude of the incoming signals and accurately detect and separate these signals. These signal processing circuits 94 generate a plurality of timing pulses designated T T and T corresponding to the time of arrival of the transmitted signals t S and S The transducer firing timing signal t and the well bore wall reflected energy timing pulse T are applied to the caliper circuit 68 (identical with the caliper circuit 68 of FIG. 2) to enable the well bore diameter to be computed.

To compensate these diameter measurements for variations in well bore fluid velocity, the T and T timing pulses are applied to a time-to-amplitude converter 95 which operates to generate a signal whose amplitude is proportional to the time separation between the T, and T timing pulses. This time-toamplitude converter 95 could take the form of caliper circuit 68 if desired. The signal output from converter 95 is then applied via a low-pass filter 98 and variable resistor 97 to the control input of the caliper circuit 68 to vary the current output therefrom as a function of the time separation between the T. and T, pulses. The variable resistor 97 can be set as desired to give the proper correction function. The low-pass filter 98 performs the same function as the low-pass filters 57 and 67a of FIG. 2.

Since the time for acoustic energy to travel from the transducer 17 to the acoustic reflecting member 84 and back again is dependent on the acoustic velocity of the well bore fluid, all other factors being constant, it can be seen that the time-toamplitude transfer function of the caliper circuit 68 will be varied in dependence on the acoustic velocity of the well bore fluid and thus the resulting diameter measurements will be independent of well bore fluid velocity. These diameter measurements are recorded by a suitable recorder 96.

While the system of FIGS. 4 and 5 will operate satisfactorily to adjust the caliper circuit 68 for variations in well bore fluid acoustic velocity, the acoustic energy emitted by the transducer 17 will be prevented from reaching the well bore wall at least once per 360 revolution of the transducer 17. For the caliper circuit 68, the problem is not important since each T pulse initiates the transfer of data to the recorder. This can be seen in FIG. 2 where the T, pulse (T is the same as the T pulse of FIG. 5) causes the transfer of data from the integrator 73 to the storage capacitor 77. Thus, if a T pulse is missing, the last valid diameter measurement (stored on capacitor 77) will be supplied to the recorder in place of the invalid diameter measurement produced in the absence of the T, pulse. Since the transducer 17 is energized approximately 2,000 times per revolution, there is very little, if any, adverse effect.

Unfortunately, the circuitry for processing the S signal for application to the recorder 96 to form a picture of the well bore wall does not have such a built-in safety feature. Turning now to FIG. 7, there is shown the signal processing circuit 94 of FIG. 5 in greater detail for purposes of showing how the S pulse can be compensated for invalid measurements caused by the acoustic reflector 84 of FIG. 4. In FIG. 7, the 2,, 8,, and S signals from the downhole tool are first applied to a detector circuit 100 which operates to produce the three timing pulses T T and T as well as the 8,, pulse itself. (While the three signals 2,, S, and 8,, have been represented in FIGS. 5 and 7 as being transmitted to the surface of the earth on separate conductors, it is possible to transmit all three pulses IOIO44 0467 on the same conductor. The circuitry for detecting the 1., and 8,. signals can be found in the copending Chapman application. The S, signal could be accurately detected by merely opening a gate a fixed time interval after each 1,, signal to determine if this S signal is present.)

The 5,, signal is applied to a contrast control circuit 101 via an inhibit gate 121. The contrast control circuit 101 operates to adjust and control the-contrast of the picture produced by the oscilloscope recorder discussed earlier (not shown). The details of this contrast control circuit 101 can be found in the copending Chapman application. The output S,,. signals from the detector circuit 100 and inhibit gate 121 are also applied to a lithology circuit (not shown here but described in the copending Chapman application) which operates to measure the peak amplitude level of the S signals per revolution or so of the transducer 17.

The contrast control circuit 101 produces signals on two output conductors 102 and 103. The signal on conductor 102 is the processed version of the applied S signal, designated S and the signal on conductor 103 is a square wave timing pulse representative of the time of occurrence of the S signal. (If desired, this signal on conductor 103 could take the place of the T timing pulse from the detector circuit 100.) These conductors 102 and 103 are connected to the inputs of an automatic gain control circuit 104.

Within the automatic gain control circuit 104, each processed S signal is applied to a variable attenuator circuit 106 and an amplifier 107. The output of the amplifier 107 is then applied to the input of a sample and hold circuit 109 which reads the peak amplitude of the signals from the amplifier 107. The sample and hold circuit 109 stores this measured peak voltage for application to a differential amplifier 110 by way ofa low-pass filter 111.

To reset the sample and hold circuit 109, the leading edge of each pulse on the conductor 103 energizes a reset one-shot 112 to generate a positive going pulse having an on-time which extends nearly to the next T pulse. At the termination of each reset pulse, the output voltage from sample and hold circuit 109 returns to the sampled level of the new pulse from amplifier 107. This output voltage is then passed by way of a resistor 113 to the non-inverting input of an operational amplifier 114. A ripple filter 115 operates to substantially remove the amplitude fluctuations arising from resetting the sample and hold circuit 109. Thus, it can be seen that the signal applied to the scope intensity input will be essentially a DC signal which changes levels whenever the picture pulses from the contrast circuit 101 changes level. By so doing, a smooth continuous image will be reproduced on film.

In the automatic gain control circuit 104, the low-pass filter 111 operates to smooth out the fluctuations in the signal from the sample and hold circuit 109. This DC signal from low-pass filter 111 is compared with a reference voltage from a gain set resistor 116 by the differential amplifier 110. The resulting difference voltage is applied to the gain adjust input of the variable attenuator 106. By this arrangement, the peak amplitude level of the output signals from amplifier 107 will be maintained, on an average, at the level set by the gain set resistor 1 16.

As discussed earlier, whenever the acoustic energy emitted from the transducer 17 strikes the acoustic reflecting member 84, at least some and perhaps all of the emitted acoustic energy will not pass to the well here wall and thus the amplitude of the resulting S signal will not be accurately representative of the condition of the well bore wall or the adjoining formation. The circuitry of FIG. 7 operates to inhibit application of the 5, signal produced during such a sequence from being processed for application to the recorder and instead utilizes the last available piece of information.

To accomplish this, in FIG. 7, the T timing pulse energizes a blanking one-shot 120 which generates a blanking pulse encompassing the time interval during which the succeeding S signal is expected. This blanking pulse from one-shot 120 energizes the inhibit gate 121 to prevent any signals from being passed to the contrast control circuit 101 just after a 8,, signal has been detected. By so doing, the reset one-shot 112 will not be energized and thus the sample and hold circuit 109 will not be reset. Thus, the sample and hold circuit 109 will continue to supply the reading obtained from the last previous measurement to the recorder and will not change this reading until receiving the next S n signal which has not been preceded by a 8,, signal.

As concerns the lithology circuit, the operation of inhibit gate 121 blanking out any S signals occurring immediately after an S signal will, in effect, cause the last valid 8,, signal to be used in place of an erroneous one. The output impedance of the inhibit gate 121, when unenergized, must be high to enable the lithology circuit to operate satisfactorily.

The systems of FIGS. 1, 2, and 4-5 could be combined, if desired, to produce further compensation. For example, the fluid compensation features of FIGS. 2 or 4-5 could be combined with the borehole diameter compensation features of FIG. 1. This is represented by the dashed line conductor 125 and variable resistor 126 fed by the filter 98 of FIG. 5 in FIG. 1. The fluid compensation output signal from the filter 98 of FIG. 5 is then combined with the borehole diameter compensation signal from filter 37 to compensate the received energy s, signals for both well bore diameter and fluid velocity. In this case, the fluid compensation variable resistor 36 of FIG. 1 could be omitted.

From the foregoing, it can be seen that methods and apparatus have been set forth for compensating acoustic well logging measurements for various well bore parameters including the acoustic impedance and velocity of the well bore fluid and the well bore diameter. These methods and apparatus have particular utility when used with a system of the type described in the copending Chapman application.

While there have been described what are at present considered to be preferred embodiments of this invention, it will be obvious to those skilled in the art that various changes and modifications may be made therein without departing from the invention, and it is, therefore, intended to cover all such changes and modifications as fall within the true spirit and scope of the invention.

What is claimed is:

1. A well logging system comprising:

a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for producing a transmitted energy sync signal representative of the time that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of at least a portion of the emitted energy which is returned to said well tool;

signal processing means responsive to at least one of said sync and received energy signals for producing a measurement signal representative of a characteristic of at least part of the media surrounding said well too];

means for measuring at least one parameter of the media surrounding said well tool which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and

means responsive to said control signal for adjusting a parameter of said signal processing means to compensate for changes in said parameter of the surrounding media.

2. The apparatus of claim 1 wherein said signal processing means includes means responsive to the amplitude of said received energy signals for providing information regarding at least a portion of the media surrounding said well too]; and wherein said control signal producing means includes means responsive to the time separation between at least some sets of sync and received energy signals for producing said control signal; and wherein said means for adjusting includes means responsive to said control signal for adjusting the amplitude of said received energy signals to compensate for variations in well bore diameter.

Ill

3. The apparatus of claim 1 wherein said means for producing a control signal includes an acoustic transmitter and at least two acoustic receivers carried by said well tool and spaced apart from each other and from said acoustic transmitter, means for repetitively energizing said acoustic transmitter to emit acoustic energy into the media surrounding said well tool, said acoustic receivers adapted to receive at least some of said emitted acoustic energy from said acoustic transmitter which passes through the well bore fluid and produce electrical signals representative thereof, means responsive to said electrical signals produced by said acoustic receivers for producing said control signal used to adjust a parameter of said signal processing means.

4. The apparatus of claim 3 wherein said signal processing means includes means responsive to the amplitude of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well tool; and wherein said means responsive to said electrical signals for producing said control signal includes means for measuring the amplitude difference between the signals produced by each of said acoustic receivers and producing said control signal in proportion to said measured amplitude difference, said control signal operating on said signal processing means to adjust the amplitude of at least some of said received energy signals to thereby compensate for variations in the acoustic impedance of the wellbore fluid surrounding said well tool.

5. The apparatus of claim 3 wherein said signal processing means includes means responsive to the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore; and wherein said means responsive to said electrical signals for producing a control signal includes means for measuring the time separation between said electrical signals produced by said two acoustic receivers and producing said control signal in proportion to said measured time separation, said control signal operating on said signal processing means to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well tool.

6. The apparatus of claim 1 wherein said means for producing a control signal includes acoustic reflector means supported by said well tool and positioned between said transducer means and a well bore wall for reflecting at least a portion of acoustic energy back to said transducer means to produce a second received energy signal, and means responsive to at least said second received energy signal for producing said control signal for application to said signal processing means to compensate for changes in an acoustic parameter of the fluid in a well bore.

7. In a well logging system, apparatus for compensating acoustic well logging measurements for variations in the crosssection of a well bore, comprising:

a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing transmitted energy sync signals representative of the times that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each energy emission, the sync and received energy signals produced for each emission of energy comprising a set of sync and received energy signals;

means for measuring the time separation between at least some sets of sync and received energy signals to produce a control signal representative of said time separation; and

means responsive to said time separation signal for adjusting the amplitude of said received energy signals to compensate said received energy signals for variations in the cross-section of said well bore.

8. The apparatus of claim 7 wherein said means for measuring the time separation to produce a control signal includes time to amplitude converter means responsive to at least some sets of said sync and received energy signals for converting the time separation between said sets of signals to a control signal whose amplitude is representative of said time separation; and wherein said means for adjusting the amplitude of said received energy signals includes variable gain means responsive to said control signal for varying the amplitude of said received energy signals as a function of the amplitude of said control signal to thereby compensate said received energy signals for variations in well bore cross-section.

9. A well logging system comprising:

a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing transmitted energy sync signals representative of the times that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each emission of energy;

signal processing means responsive to at least one of said sync and received energy signals for producing a signal representative of a characteristic of at least part of the media surrounding said well too];

an acoustic transmitter and two acoustic receivers supported by said well too], means for repetitively energizing said acoustic transmitter to emit acoustic energy into the media surrounding said well tool, said acoustic receivers adapted to receive at least some of said emitted acoustic energy from said acoustic transmitter and produce electrical signals representative thereof;

means responsive to said electrical signals produced by said acoustic receivers for producing a control signal representative of an acoustic parameter of the fluid in a well bore; and

adjusting means responsive to said control signal for adjusting a parameter of said signal processing means to compensate for changes in said well bore fluid acoustic parameter.

10. The apparatus of claim 9 wherein said signal processing means includes means responsive to the amplitudes of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well too]; and wherein said means responsive to said electrical signals for producing a control signal includes means for mea- Suring the amplitude difference between the signals produced by each of said acoustic receivers and producing said control signal in proportion to said measured amplitude difference, said control signal operating on said signal processing means to adjust the amplitude of at least some of said received energy signals to thereby compensate for variations in the acoustic impedance of the well bore fluid surrounding said well too].

1 1. The apparatus of claim 9 wherein said signal processing means includes means responsive to the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore, and wherein said means responsive to said electrical signals for producing a control signal includes means for measuring the time separation between said electrical signals produced by said two acoustic receivers and producing said control signal in proportion to said measured time separation, said control signal operating on said signal processing means to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well tool.

12. The apparatus of claim wherein said means for measuring said amplitude difierence includes means operative in a time relationship with the energization of said acoustic transmitter for sampling the amplitude of a selected portion of said electrical signal produced by each of said acoustic receivers, means for subtracting the sampled amplitude of the electrical signal from one of said acoustic receivers from that produced by the other of said acoustic receivers to produce a difference signal, low pass filter means for filtering said difference signal to produce said control signal; and wherein said adjusting means includes variable means for adjusting the amplitude of said received energy signals as a function of the amplitude of said control signal to compensate for variations in well bore fluid impedance.

13. The apparatus of claim 9 wherein said signal processing means includes means responsive to said sync and received energy signals for generating a pulse of a substantially constant current having a time duration representative of the time spacing between successive sync and received energy signals, integrator means responsive to said current pulse for producing a signal whose amplitude is representative of said time spacing, and output means responsive to said time spacing representative signal for producing an output signal representative of the cross-section of a well bore; and wherein said control signal producing means includes means operative in a time relationship with the energization of said acoustic transmitter for separating the electrical signals produced by each of said acoustic receivers, time to amplitude conversion means responsive to said separated electrical signals for producing a signal representative of the time separation between successive ones of said separated electrical signals, and low pass filter means responsive to said time separation representative signal for producing said control signal; and wherein said adjusting means includes means for varying the magnitude of current applied to said integrator means in response to said control signal to thereby compensate cross-section representative output signal for variations in the well bore fluid acoustic velocity.

14 A well logging system comprising:

a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing a transmitted energy signal representative of the time that said energy is emitted, means coupled to said transducer means for producing a first received energy signal representative of that portion of the emitted energy which is returned to said well tool from a well bore wall;

acoustic reflector means supported by said tool and posi tioned between said transducer and a well bore wall for reflecting at least a portion of at least one burst of acoustic energy back to said transducer means to produce a second received energy signal;

signal processing means responsive to said sync and first received energy signals for producing an output signal representative of a characteristic of at least part of the media surrounding said well tool; and

compensation means responsive to at least said second received energy signal for producing a control signal for use in adjusting a parameter of said signal processing means to compensate said output signal for changes in an acoustic parameter of the fluid in a well bore.

15. The apparatus of claim 14 wherein said compensation means includes first time to amplitude conversion means responsive to the time separation between at least one sync signal and a successive second received energy signal for producing said control signal representative of said time separation; and wherein said signal processing means includes second time to amplitude conversion means responsive to the time separation between successive sync and first received energy signals for producing a signal representative of the distance between said well tool and at least one part of the well bore wall, said control signal operating to vary the transfer characteristic of said second time to amplitude conversion means to thereby compensate for changes in well bore fluid velocity.

16. The apparatus of claim 14 and further including means responsive to each second received energy signal for preventing said signal processing means from changing the state of said output signal whenever such a second received energy signal is produced, whereby the interception of acoustic energy by said acoustic reflector means will not adversely affect the character of. said output signal which is representative of the surrounding media.

17. The apparatus of claim 15 and further including means responsive to each second received energy signal for preventing said signal processing means from changing the state of said output signal whenever such a second received energy signal is produced whereby the interception of acoustic energy by said acoustic reflector means will not adversely affect the character of said output signal which is representative of the surrounding media.

18. A well logging system comprising:

a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means coupled to said transducer means for producing a first received energy signal representative of that portion of the emitted energy which is returned to said well tool from a well bore wall;

acoustic reflector means supported by said tool and positioned between said transducer and a borehole wall for reflecting at least a portion of at least one burst of acoustic energy back to said transducer means to produce a second received energy signal;

signal processing means responsive to at least said first received energy signal for producing an output signal representative of a characteristic of at least part of the media surrounding said well tool; and

means responsive to at least said second received energy signal for adjusting a parameter of said signal processing means to compensate said output signal for changes in an acoustic parameter of the fluid in a borehole.

19. A method of investigating the media surrounding a well tool in a well bore, comprising:

moving a well logging tool through a wellbore; repetitively emitting acoustic energy into a media surrounding said well tool; at least a portion of said energy being reflected off of a wellbore wall and returned toward said well tool;

producing a transmitted energy sync signal representative of the time that said energy is emitted; receiving said reflected energy and producing a received energy signal representative of at least a portion of the emitted energy which is returned to said well tool;

producing a measurement signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals;

measuring at least one parameter of the media surrounding said well too] which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and

using said control signal to compensate said measurement signal for changes in said parameter of the surrounding media.

20. A method of investigating the media surrounding a well tool in a well bore, comprising:

moving a well logging tool having a transducer means through a well bore; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool while rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, producing transmitted energy sync signals representative of the times that said energy is emitted, producing a received energy signal representation of that portion of the emitted energy which is returned to said well tool for each emission of energy; producing a measurement signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals; measuring at least one parameter of the media surrounding said well too] which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and compensating said measurement signal processing for changes in said parameter of the surrounding media in response to said control signal. 21. A method of compensating acoustic well logging measurements for variations in the cross-section of a well bore, comprising:

moving a well logging tool having transducer means through v a borehole; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool; rotating said transducer means so that emitted energy will be sequentially directed at various circumferential portions of a well bore wall; producing transmitted energy signals representative of the times that said energy is emitted; producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each energy emission, the sync and received energy signals produced for each emission of energy comprising a set of sync and received energy signals; and

adjusting the amplitude of said received energy signals as a function of said measured time separation to compensate said received energy signals for variations in the crosssection of a well bore.

22. The method of claim 22 wherein the step of measuring the time separation includes converting the time separation between at least some of said sets of sync and received energy signals to a control signal whose amplitude is representative of said time separation; and wherein the step of adjusting the amplitude of said received energy signals includes varying the amplitude of said received energy signals as a function of the amplitude of said control signal to thereby compensate said received energy signals for variation in well bore cross-section.

23. A method of investigating the media surrounding a well tool in a well bore, comprising:

moving a well logging tool having transducer means through a well bore; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool; rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall; producing transmitted energy sync signals representative of the times that said energy is emitted; producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each emission of energy;

producing a signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals; repetitively emitting acoustic energy from a point spaced apart from said transducer means into the media surrounding said well tool; receiving at least some of said emitted acoustic energy from said acoustic transmitter at two points spaced apart from said transducer means and producing electrical signals representative thereof;

measuring a relationship between said electrical signals for producing a control signal representative of an acoustic parameter of the fluid in a well bore; and

compensating said received energy signals for changes in said well bore fluid acoustic parameter in response to said control si nal. 24. The met 0d of claim 23 wherein the step of producing a signal representative of said surrounding media characteristic includes using the amplitudes of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well tool; and wherein the step of producing a control signal includes the steps of measuring the amplitude difference between said electrical signals and producing said control signal in proportion to said measured amplitude difference, and using said control signal to adjust the amplitude of at least some of said received energy signals to thereby compensate for variations in the acoustic impedance of the well bore fluid surrounding said well tool.

25. The method of claim 23 wherein the step of producing a signal representative of said surrounding media characteristic includes the step of measuring the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore; and wherein the step of producing a control signal includes the steps of measuring the time separation between said electrical signals produced in response to energy received at said two points and producing said control signal in proportion to said measured time separation, and using said control signal to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well too].

26. A method of investigating a media surrounding a well tool, comprising:

moving a well logging tool having transducer means through a wellbore; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well too]; rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a wellbore wall, at least a portion of at least one burst of acoustic energy being reflected back to said transducer means through the fluid in a wellbore before reaching a wellbore wall to produce a first received energy signal; producing a transmitted energy sync signal representative of the time that said energy is emitted; producing a second received energy signal representative of that portion of the emitted energy which is returned to said well tool from a wellbore wall; and producing an output signal representative of a characteristic of at least part of the media surrounding said well tool in response to said sync and first and second received energy signals, said first received signals being used to compensate for changes in an acoustic parameter of the fluid in a well bore. 

1. A well logging system comprising: a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for producing a transmitted energy sync signal representative of the time that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of at least a portion of the emitted energy which is returned to said well tool; signal processing means responsive to at least one of said sync and received energy signals for producing a measurement signal representative of a characteristic of at least part of the media surrounding said well tool; means for measuring at least one parameter of the media surrounding said well tool which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and means responsive to said control signal for adjusting a parameter of said signal processing means to compensate for changes in said parameter of the surrounding media.
 2. The apparatus of claim 1 wherein said signal processing means includes means responsive to the amplitude of said received energy signals for providing information regarding at least a portion of the media surrounding said well tool; and wherein said control signal producing means includes means responsive to the time separation between at least some sets of sync and received energy signals for producing said control signal; and wherein said means for adjusting includes means responsive to said control signal for adjusting the amplitude of said received energy signals to compensate for variations in well bore diameter.
 3. The apparatus of claim 1 wherein said means for producing a control signal includes an acoustic transmitter and at least two acoustic receivers carried by said well tool and spaced apart from each other and from said acoustic transmitter, means for repetitively energizing said acoustic transmitter to emit acoustic energy into the media surrounding said well tool, said acoustic receivers adapted to receive at least some of said emitted acoustic energy from said acoustic transmitter which passes through the well bore fluid and produce electrical signals representative thereof, means responsive to said electrical signals produced by said acoustic receivers for producing said control signal used to adjust a parameter of said signal processing means.
 4. The apparatus of claim 3 wherein said signal processing means includes means responsive to the amplitude of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well tool; and wherein said means responsive to said electrical signals for producing said control signal includes means for measuring the amplitude difference between the signals produced by each of said acoustic receivers and producing said control signal in proportion to said measured amplitude difference, said control signal operating on said signal processing means to adjust the amplitude of at least some of said received energy signals to theReby compensate for variations in the acoustic impedance of the wellbore fluid surrounding said well tool.
 5. The apparatus of claim 3 wherein said signal processing means includes means responsive to the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore; and wherein said means responsive to said electrical signals for producing a control signal includes means for measuring the time separation between said electrical signals produced by said two acoustic receivers and producing said control signal in proportion to said measured time separation, said control signal operating on said signal processing means to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well tool.
 6. The apparatus of claim 1 wherein said means for producing a control signal includes acoustic reflector means supported by said well tool and positioned between said transducer means and a well bore wall for reflecting at least a portion of acoustic energy back to said transducer means to produce a second received energy signal, and means responsive to at least said second received energy signal for producing said control signal for application to said signal processing means to compensate for changes in an acoustic parameter of the fluid in a well bore.
 7. In a well logging system, apparatus for compensating acoustic well logging measurements for variations in the cross-section of a well bore, comprising: a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing transmitted energy sync signals representative of the times that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each energy emission, the sync and received energy signals produced for each emission of energy comprising a set of sync and received energy signals; means for measuring the time separation between at least some sets of sync and received energy signals to produce a control signal representative of said time separation; and means responsive to said time separation signal for adjusting the amplitude of said received energy signals to compensate said received energy signals for variations in the cross-section of said well bore.
 8. The apparatus of claim 7 wherein said means for measuring the time separation to produce a control signal includes time to amplitude converter means responsive to at least some sets of said sync and received energy signals for converting the time separation between said sets of signals to a control signal whose amplitude is representative of said time separation; and wherein said means for adjusting the amplitude of said received energy signals includes variable gain means responsive to said control signal for varying the amplitude of said received energy signals as a function of the amplitude of said control signal to thereby compensate said received energy signals for variations in well bore cross-section.
 9. A well logging system comprising: a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing transmitted energy sync signals representative of the times that said energy is emitted, means coupled to said transducer means for producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each emission of energy; signal processing means responsive to at least one of said sync and received energy signals for producing a signal representative of a characteristic of at least part of the media surrounding said well tool; an acoustic transmitter and two acoustic receivers supported by said well tool, means for repetitively energizing said acoustic transmitter to emit acoustic energy into the media surrounding said well tool, said acoustic receivers adapted to receive at least some of said emitted acoustic energy from said acoustic transmitter and produce electrical signals representative thereof; means responsive to said electrical signals produced by said acoustic receivers for producing a control signal representative of an acoustic parameter of the fluid in a well bore; and adjusting means responsive to said control signal for adjusting a parameter of said signal processing means to compensate for changes in said well bore fluid acoustic parameter.
 10. The apparatus of claim 9 wherein said signal processing means includes means responsive to the amplitudes of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well tool; and wherein said means responsive to said electrical signals for producing a control signal includes means for measuring the amplitude difference between the signals produced by each of said acoustic receivers and producing said control signal in proportion to said measured amplitude difference, said control signal operating on said signal processing means to adjust the amplitude of at least some of said received energy signals to thereby compensate for variations in the acoustic impedance of the well bore fluid surrounding said well tool.
 11. The apparatus of claim 9 wherein said signal processing means includes means responsive to the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore, and wherein said means responsive to said electrical signals for producing a control signal includes means for measuring the time separation between said electrical signals produced by said two acoustic receivers and producing said control signal in proportion to said measured time separation, said control signal operating on said signal processing means to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well tool.
 12. The apparatus of claim 10 wherein said means for measuring said amplitude difference includes means operative in a time relationship with the energization of said acoustic transmitter for sampling the amplitude of a selected portion of said electrical signal produced by each of said acoustic receivers, means for subtracting the sampled amplitude of the electrical signal from one of said acoustic receivers from that produced by the other of said acoustic receivers to produce a difference signal, low pass filter means for filtering said difference signal to produce said control signal; and wherein said adjusting means includes variable means for adjusting the amplitude of said received energy signals as a function of the amplitude of said control signal to compensate for variations in well bore fluid impedance.
 13. The apparatus of claim 9 wherein said signal processing means includes means responsive to said sync and received energy signals for generating a pulse of a substantially constant current having a time duration representative of the time spacing between successive sync and received energy signals, integrator means responsive to said current pulse for producing a signal whose amplitude is representative of said time spacing, and output means responsive to said time spacing representative signal for producing an output signal representative of the cross-section of a well bore; and wherein said control signal prOducing means includes means operative in a time relationship with the energization of said acoustic transmitter for separating the electrical signals produced by each of said acoustic receivers, time to amplitude conversion means responsive to said separated electrical signals for producing a signal representative of the time separation between successive ones of said separated electrical signals, and low pass filter means responsive to said time separation representative signal for producing said control signal; and wherein said adjusting means includes means for varying the magnitude of current applied to said integrator means in response to said control signal to thereby compensate cross-section representative output signal for variations in the well bore fluid acoustic velocity.
 14. A well logging system comprising: a well logging tool having transducer means, means for repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool, means for rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, means for producing a transmitted energy signal representative of the time that said energy is emitted, means coupled to said transducer means for producing a first received energy signal representative of that portion of the emitted energy which is returned to said well tool from a well bore wall; acoustic reflector means supported by said tool and positioned between said transducer and a well bore wall for reflecting at least a portion of at least one burst of acoustic energy back to said transducer means to produce a second received energy signal; signal processing means responsive to said sync and first received energy signals for producing an output signal representative of a characteristic of at least part of the media surrounding said well tool; and compensation means responsive to at least said second received energy signal for producing a control signal for use in adjusting a parameter of said signal processing means to compensate said output signal for changes in an acoustic parameter of the fluid in a well bore.
 15. The apparatus of claim 14 wherein said compensation means includes first time to amplitude conversion means responsive to the time separation between at least one sync signal and a successive second received energy signal for producing said control signal representative of said time separation; and wherein said signal processing means includes second time to amplitude conversion means responsive to the time separation between successive sync and first received energy signals for producing a signal representative of the distance between said well tool and at least one part of the well bore wall, said control signal operating to vary the transfer characteristic of said second time to amplitude conversion means to thereby compensate for changes in well bore fluid velocity.
 16. The apparatus of claim 14 and further including means responsive to each second received energy signal for preventing said signal processing means from changing the state of said output signal whenever such a second received energy signal is produced, whereby the interception of acoustic energy by said acoustic reflector means will not adversely affect the character of said output signal which is representative of the surrounding media.
 17. The apparatus of claim 15 and further including means responsive to each second received energy signal for preventing said signal processing means from changing the state of said output signal whenever such a second received energy signal is produced whereby the interception of acoustic energy by said acoustic reflector means will not adversely affect the character of said output signal which is representative of the surrounding media.
 18. A well logging system comprising: a well logging tool having transducer means, means for repetitively energizing said transducer mEans to emit acoustic energy into a media surrounding said well tool, means coupled to said transducer means for producing a first received energy signal representative of that portion of the emitted energy which is returned to said well tool from a well bore wall; acoustic reflector means supported by said tool and positioned between said transducer and a borehole wall for reflecting at least a portion of at least one burst of acoustic energy back to said transducer means to produce a second received energy signal; signal processing means responsive to at least said first received energy signal for producing an output signal representative of a characteristic of at least part of the media surrounding said well tool; and means responsive to at least said second received energy signal for adjusting a parameter of said signal processing means to compensate said output signal for changes in an acoustic parameter of the fluid in a borehole.
 19. A method of investigating the media surrounding a well tool in a well bore, comprising: moving a well logging tool through a wellbore; repetitively emitting acoustic energy into a media surrounding said well tool; at least a portion of said energy being reflected off of a wellbore wall and returned toward said well tool; producing a transmitted energy sync signal representative of the time that said energy is emitted; receiving said reflected energy and producing a received energy signal representative of at least a portion of the emitted energy which is returned to said well tool; producing a measurement signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals; measuring at least one parameter of the media surrounding said well tool which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and using said control signal to compensate said measurement signal for changes in said parameter of the surrounding media.
 20. A method of investigating the media surrounding a well tool in a well bore, comprising: moving a well logging tool having a transducer means through a well bore; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool while rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall, producing transmitted energy sync signals representative of the times that said energy is emitted, producing a received energy signal representation of that portion of the emitted energy which is returned to said well tool for each emission of energy; producing a measurement signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals; measuring at least one parameter of the media surrounding said well tool which affects the accuracy of said measurement signal and producing a control signal representative of said parameter; and compensating said measurement signal processing for changes in said parameter of the surrounding media in response to said control signal.
 21. A method of compensating acoustic well logging measurements for variations in the cross-section of a well bore, comprising: moving a well logging tool having transducer means through a borehole; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool; rotating said transducer means so that emitted energy will be sequentially directed at various circumferential portions of a well bore wall; producing transmitted energy signals representative of the times that said energy is emitted; producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each energy emission, the sync and received energy signals produced for each emission of energy comprising a set of sync and received energy signals; and adjusting the amplitude of said received energy signals as a function of said measured time separation to compensate said received energy signals for variations in the cross-section of a well bore.
 22. The method of claim 22 wherein the step of measuring the time separation includes converting the time separation between at least some of said sets of sync and received energy signals to a control signal whose amplitude is representative of said time separation; and wherein the step of adjusting the amplitude of said received energy signals includes varying the amplitude of said received energy signals as a function of the amplitude of said control signal to thereby compensate said received energy signals for variation in well bore cross-section.
 23. A method of investigating the media surrounding a well tool in a well bore, comprising: moving a well logging tool having transducer means through a well bore; repetitively energizing said transducer means to emit acoustic energy into a media surrounding said well tool; rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a well bore wall; producing transmitted energy sync signals representative of the times that said energy is emitted; producing a received energy signal representative of that portion of the emitted energy which is returned to said well tool for each emission of energy; producing a signal representative of a characteristic of at least part of the media surrounding said well tool in response to at least one of said sync or received energy signals; repetitively emitting acoustic energy from a point spaced apart from said transducer means into the media surrounding said well tool; receiving at least some of said emitted acoustic energy from said acoustic transmitter at two points spaced apart from said transducer means and producing electrical signals representative thereof; measuring a relationship between said electrical signals for producing a control signal representative of an acoustic parameter of the fluid in a well bore; and compensating said received energy signals for changes in said well bore fluid acoustic parameter in response to said control signal.
 24. The method of claim 23 wherein the step of producing a signal representative of said surrounding media characteristic includes using the amplitudes of at least some of said received energy signals for providing information concerning at least a portion of the media surrounding said well tool; and wherein the step of producing a control signal includes the steps of measuring the amplitude difference between said electrical signals and producing said control signal in proportion to said measured amplitude difference, and using said control signal to adjust the amplitude of at least some of said received energy signals to thereby compensate for variations in the acoustic impedance of the well bore fluid surrounding said well tool.
 25. The method of claim 23 wherein the step of producing a signal representative of said surrounding media characteristic includes the step of measuring the time separation between selected sync and received energy signals for producing measurements representative of the cross-section of a well bore; and wherein the step of producing a control signal includes the steps of measuring the time separation between said electrical signals produced in response to energy received at said two points and producing said control signal in proportion to said measured time separation, and using said control signal to compensate said cross-section measurements for variations in the acoustic velocity of the well bore fluid surrounding said well tool.
 26. A method of investigating a media surrounding a well tool, comprising: moving a well logging tool having transducer means through a wellbore; repetitively energiZing said transducer means to emit acoustic energy into a media surrounding said well tool; rotating said transducer means so that said emitted energy will be sequentially directed at various circumferential portions of a wellbore wall, at least a portion of at least one burst of acoustic energy being reflected back to said transducer means through the fluid in a wellbore before reaching a wellbore wall to produce a first received energy signal; producing a transmitted energy sync signal representative of the time that said energy is emitted; producing a second received energy signal representative of that portion of the emitted energy which is returned to said well tool from a wellbore wall; and producing an output signal representative of a characteristic of at least part of the media surrounding said well tool in response to said sync and first and second received energy signals, said first received signals being used to compensate for changes in an acoustic parameter of the fluid in a well bore. 